export compressor instability detection using system 1* and proficy** smartsignal software

Transcription

1 BP MAGNUS PLATFORM export compressor instability detection using system 1* and proficy** smartsignal software part 1 58 ORBIT Vol.32 No.3 Jul.2012

2 THIS CASE STUDY DESCRIBES AN EXAMPLE OF A GAS COMPRESSOR THRUST POSITION INSTABILITY PROBLEM ON A BP OFFSHORE DRILLING & PRODUCTION FACILITY. Peter Griffiths Production Enhancement Team Leader BP North Sea Dave Watson Reliability and Maintenance Team Leader BP North Sea Linda Alrabady GE Oil & Gas Machinery Diagnostic Services (MDS) Lead Engineer Linda.Alrabady@ge.com The problem occurred when the multistage centrifugal natural gas compressor was operated at significantly reduced loads. Happily, BP had recently deployed real time condition monitoring & anomaly detection technologies in order to improve the reliability of the offshore rotating equipment. These included GE s Bently Nevada System 1 and Proficy SmartSignal Shield software, which were deployed per BP defined practices. The software installations were combined with a GE Supporting Services Agreement (SSA) to ensure access to the right skills. SmartSignal Shield software had been installed four months before the events described here, and was able to flag the compressor instability at a very early stage. Additionally, System 1 software provided confirmation of the problem by accommodating deeper diagnostic analysis. The rotating equipment team was quickly notified of the problem. Working with the offshore team, they routed the wells differently to manage load on the affected compressor. They also opened the compressor anti-surge valve manually to increase recycle flow and stabilize the rotor. These prompt actions implemented a short-term solution, which avoided failure of the compressor and unplanned shutdowns of the affected system. A future article will describe Part 2 of this case study, which will address long-term solutions to the root cause of the problem. Historically, there have been several instability-related failures to the compressor thrust bearing, and in the past six months there have been at least 4 trips. This case history demonstrates how effective use of the software platform enabled quick sharing of important information across the region - enhancing plant safety while at the same time avoiding the lost production that a compressor failure would have caused. Jul.2012 No.3 Vol.32 ORBIT 59

3 Site Overview The BP Magnus platform is a combined drilling and production platform in one of the UK s most northerly fields, located in the North Sea, 160 km northeast of Shetland, Scotland. The oilfield was discovered in At peak production times, the platform can produce 156,000 bpd oil, 12,000 bpd gas condensate and 60 mmscfd natural gas. The platform s gas processing plant includes two separate trains which each have three sections: flash gas, gas drying and chilling & export compression. Before export compression, the gas is first fed to a suction drum where liquids are accumulated and drained. The gas is then compressed in the Low-Pressure first stage (LP Compressor) after which it passes through the first stage aftercooler to the High-Pressure second stage (HP Compressor) and the second stage aftercooler. Machine Train Description The compressor described in this case study is one of two multistage vertically split centrifugal compressors with electric motor drive via a speed increasing gearbox (Figure 1). The axial thrust due to the gas pressure difference is mostly balanced using a balance drum. However, since some residual axial load may exist during operation, a tilting-pad double thrust bearing is used to avoid the possibility of damage to the labyrinth-type shaft seals (Figure 2). Both the LP and the HP compressor use fluid-film bearings, and vibration is monitored using XY radial vibration transducers. Events Sequence The first indication of the problem came when the SmartSignal Shield software flagged an advisory of a thrust position problem due to significant and persistent deviation from the normal condition. It was clear at the time that there was a high correlation between the changing compressor load and the rotor thrust position. As part of BP s existing SSA coverage, a GE Machinery Diagnostic Engineer in the UK observed the alarm in the BP Dyce office, performed initial evaluation of the situation and discussed the issue with the SmartSignal team in Chicago USA, quickly notifying the customer of the evolving situation. Further analysis of the situation was required as the data from the SmartSignal installation was sampled every 10 minutes. When the thrust instability occurred, the System 1 platform had been online for less than a week, but had been acquiring data at high sampling rates. The System 1 data (Figures 3 through 7) clearly indicated that thrust displacement started to ramp up along with significantly reduced load, high pressure ratio, low flow rate and no significant response from the antisurge valve on 04APR12. FIGURE 1: This simplified machine train diagram shows Export Compressor Train 1. Not shown here are the suction drum before the LP Compressor, and the aftercoolers after each compressor s discharge. 6 ORBIT Vol.32 No.3 Jul.2012

4 FIGURE 2: This photo shows the self-equalizing tilting pad double thrust bearing from the HP Compressor described in this article. FIGURE 4: Export Compressor A Motor Load (Current) Trend. The lower than normal motor load on 04APR12 corresponds to the period of low compressor flow and instability described in this article. FIGURE 3: HP Compressor Thrust Position Trend. The horizontal red line (labelled) indicates the trip setpoint for axial thrust position. Rotor position closely approached the trip setpoint (at mm) during the period of low flow and instability on 04APR12. But after corrective actions were implemented, the rotor position returned to normal. Jul.2012 No.3 Vol.32 ORBIT 6

5 FIGURE 5: HP Compressor Pressure Ratio Trend. The higher than normal pressure ratio on 04APR12 corresponds to the period of low compressor flow and instability described in this article. FIGURE 6: HP Compressor Flow Rate Trend. Following the period of low flow on 04APR12, compressor flow was restored to normal on 05APR12. FIGURE 7: HP Compressor Antisurge Valve Opening Position Trend. Observe that the valve did not respond as anticipated during the period of the flow instability on 04APR12. 6 ORBIT Vol.32 No.3 Jul.2012

6 The anti-surge control system is used to prevent the compressor from surging by recycling gas from the compressor discharge side to the suction drum. This provides the minimum flow rate required to keep the compressor running at an adequate margin from the surge threshold. Several different parameters are fed to the control system to allow it to calculate the required recycle valve position. These include compressor suction flow rate and inlet temperature and differential pressure between the compressor suction and discharge pressures (used to compensate for varying conditions of suction pressure and gas molecular weight). Although both the LP and HP Compressors were running at reduced load only the HP compressor suffered from a condition of instability. The situation directed suspicions towards the antisurge control system on the HP compressor. As seen in Figure 7, the valve position showed no significant changes i.e. less than 4% even though the compressor was in surge mode. To support this finding, System 1 data was reviewed in several different steady-state and transient formats. Figures 8 through 10 show the vibration spectrums from thrust bearing position measurements for the HP and LP Compressor and the Gearbox High Speed Shaft. THIS CASE HISTORY WAS A GREAT EXAMPLE OF HOW THE CONDITION MONITORING PLATFORM ALLOWED ENHANCING THE SAFETY OF THE PLANT OPERATION, WHILE AT THE SAME TIME AVOIDING LOST PRODUCTION. With the machine train speed at 12,450 rpm, 1X vibration frequency is Hz. This 1X peak can be seen for all three thrust bearings. However, the HP compressor thrust bearing vibration also showed a very dominant frequency peak at 0.22X (45 Hz), while the LP Compressor and Gearbox did not. A potential cause for such subsynchronous vibration is aerodynamic excitation (i.e., stall or surge). The waterfall plot for the HP Compressor Drive End (DE) bearing for the duration of 22MARCH2012 to 21APRIL2012 is shown in Figure 11. This plot shows several regions of instability with two main subsynchronous components (0.22X & 0.459X). Both of these components are forward in the full spectrum plot, which indicates that their precession is the same as the direction of rotation for the machine. The origin of the 0.459X will be discussed in Part 2 of this case study, which we will share as a future Orbit article. For now, we can say that this frequency is in the range of a classic fluid induced instability condition such as oil whirl or whip. We know that tilting pad bearings typically do not show such behaviour, so our next candidate would be the shaft seals on the compressor. These include both labyrinth type gas seals and sleeve type oil seals. Jul.2012 No.3 Vol.32 ORBIT 6

7 FIGURE 8: HP Compressor Thrust Vibration Spectrum. The 45 Hz peak corresponds to a vibration frequency of 0.22X. This is a classic symptom of stall/surge in turbocompressors. FIGURE 9: LP Compressor Thrust Vibration Spectrum. Again, the Hz peak corresponds to 1X vibration, and it is obvious that there is only a very small component at 0.22X. 64 ORBIT Vol.32 No.3 Jul.2012

8 FIGURE 10: Gearbox High Speed Shaft Thrust Vibration Spectrum. Figures 12 through 14 show the orbit timebase (waveform) plots and spectrums before, during and after the period of compressor instability for vibration measured at the HP Compressor DE bearing. These plots show conditions for compressor load that was normal, significantly lower than normal, and normal, respectively. Observe that the 0.22X component (circled) appeared when the compressor was running at significantly reduced load and then disappeared when load was restored to normal. Corrective Actions After confirming the root cause of the instability (using System 1 and SmartSignal Shield software) to be a combination of significantly reduced load and a problem with the HP Compressor antisurge control system, the rotating equipment team was notified. Working with the offshore team, they ensured that the production wells were routed differently to manage the compressor load and that the antisurge valve was manually opened to increase the recycle flow rate and stabilize the rotor (Figure 3). As levels were approaching the thrust position trip level ( mm), timely intervention saved the platform from the consequences of a machine trip and a potential thrust bearing failure resulting in the avoidance of a $1 million (USD) net cash deferral. As a result of this event, BP demonstrated the ability to quickly share important information across the region to prevent similar future events. Jul.2012 No.3 Vol.32 ORBIT 65

9 FIGURE 11: HP Compressor DE Bearing waterfall plot. Conclusions The export gas compressor loading is dictated by production demand at any particular time. Ideally, the compressor should be operated very close to its Best Efficiency Point (BEP) whenever possible. However, it is also very important to avoid operating the compressor beyond its surge threshold, which occurs at a combination of high head and low flow. When compressor surge occurs, the rapidly fluctuating thrust loads can be very destructive, and can cause major damage to the machine. The second part of this case study will address long term solutions to the instability conditions described in this article, and will provide additional detail into the observed 0.459X subsynchronous vibration component and its relation to the rotor instability. Copyright 2012 General Electric Company. All rights reserved. * denotes a trademark of Bently Nevada, Inc., a wholly owned subsidiary of General Electric Company. ** Trademark of GE Intelligent Platforms, Inc. SmartSignal is a trademark of SmartSignal Corporation, a wholly owned subsidiary of GE Intelligent Platforms, Inc. 66 ORBIT Vol.32 No.3 Jul.2012

10 FIGURE 12: Orbit timebase and spectrum plots BEFORE the period of reduced compressor load. FIGURE 13: Orbit timebase and spectrum plots DURING the period of reduced compressor load. Observe the subsynchronous peak at 0.22X (circled). FIGURE 14: Orbit timebase and spectrum plots AFTER the period of reduced compressor load. Observe that the subsynchronous peak at 0.22X is no longer present. Jul.2012 No.3 Vol.32 ORBIT 67